Mud telemetry with rotating control device

ABSTRACT

An example rotating control device may include a bearing assembly with at least one rotating seal and a pressure modulator coupled to the bearing assembly. A controller may be communicably coupled to the pressure modulator. The pressure modulator may be at least one of a mud pulser, a mud siren, and a pressure transducer. The pressure transducer may be a piezoelectric transducer.

BACKGROUND

The present disclosure relates generally to well drilling operations and, more particularly, to mud telemetry with a rotating control device (“RCD”).

With the increasing demand for hydrocarbons, the effective and efficient development of subterranean formations containing hydrocarbons has become critical. A number of different operations are performed in order to develop a subterranean formation and extract desired hydrocarbons therefrom. Such operations may include, but are not limited to, drilling operations, fracturing operations, and completion operations. During drilling operations, a borehole in the subterranean formation is created. The borehole may intersect areas of the formation in which fluids are trapped under high pressure.

In certain instances, these pressurized formation fluids, including hydrocarbons, may try to escape into the borehole. Typically, the pressure within the borehole is maintained at a high enough level to prevent movement of the pressurized formation fluids into the borehole until a desired time. In underbalanced or managed-pressure drilling applications, the pressure within the borehole is lower and some of the pressurized formation fluids may be allowed to escape into the borehole. RCD's may be inserted immediately above or into the borehole, or otherwise placed to prevent the pressurized fluids from escaping, uncontrolled, at the surface, which is typically characterized as a “blowout” condition. Communicating with RCDs while they are inaccessible may be necessary in many instances but difficult to accomplish, particularly in “off-shore” drilling operations where communications require the use of additional equipment that increases the cost of the drilling operation.

FIGURES

Some specific exemplary embodiments of the disclosure may be understood by referring, in part, to the following description and the accompanying drawings.

FIG. 1 is a diagram of an example drilling system, according to aspects of the present disclosure.

FIG. 2 is a diagram of an example RCD, according to aspects of the present disclosure.

FIG. 3 is a diagram of an example information handling system, according to aspects of the present disclosure.

FIG. 4 is a flow diagram illustrating an example method according to aspects of the present disclosure

While embodiments of this disclosure have been depicted and described and are defined by reference to exemplary embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure.

DETAILED DESCRIPTION

For purposes of this disclosure, an information handling system may include any instrumentality or aggregate of instrumentalities operable to compute, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes. For example, an information handling system may be a personal computer, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price. The information handling system may include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, ROM, and/or other types of nonvolatile memory. Additional components of the information handling system may include one or more disk drives, one or more network ports for communication with external devices as well as various input and output (I/O) devices, such as a keyboard, a mouse, and a video display. The information handling system may also include one or more buses operable to transmit communications between the various hardware components. It may also include one or more interface units capable of transmitting one or more signals to a controller, actuator, or like device.

For the purposes of this disclosure, computer-readable media may include any instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a period of time. Computer-readable media may include, for example, without limitation, storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory; as well as communications media such wires, optical fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or any combination of the foregoing.

Illustrative embodiments of the present disclosure are described in detail herein. In the interest of clarity, not all features of an actual implementation may be described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions are made to achieve the specific implementation goals, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure.

To facilitate a better understanding of the present disclosure, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the disclosure. Embodiments of the present disclosure may be applicable to horizontal, vertical, deviated, or otherwise nonlinear wellbores in any type of subterranean formation. Embodiments may be applicable to injection wells as well as production wells, including hydrocarbon wells. Embodiments may be implemented using a tool that is made suitable for testing, retrieval and sampling along sections of the formation. Embodiments may be implemented with tools that, for example, may be conveyed through a flow passage in tubular string or using a wireline, slickline, coiled tubing, downhole robot or the like.

The terms “couple” or “couples” as used herein are intended to mean either an indirect or a direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection or through an indirect mechanical or electrical connection via other devices and connections. Similarly, the term “communicatively coupled” as used herein is intended to mean either a direct or an indirect communication connection. Such connection may be a wired or wireless connection such as, for example, Ethernet or LAN. Such wired and wireless connections are well known to those of ordinary skill in the art and will therefore not be discussed in detail herein. Thus, if a first device communicatively couples to a second device, that connection may be through a direct connection, or through an indirect communication connection via other devices and connections.

FIG. 1 is an illustration of an example off-shore drilling system 100, incorporating aspects of the present disclosure. In the embodiment shown, the drilling system 100 comprises an offshore drilling rig 102 positioned above a subterranean formation 104 and a volume of water 106 covering the surface 108 of the formation 104, otherwise referred to as the sea bed. In certain embodiments, the drilling rig 102 may be floating on the surface of the volume of water 106 and subject to the tides and movement of the water 106, or anchored to the formation 104 and raised such that the drilling rig 102 is substantially unaffected by the movement of the water 106, such as in a “jack up” style rig.

The drilling system 100 may include a casing 110 that extends into the formation 104 and is secured against axial movement by cement. The casing 110 may extend above the surface 108 of the formation 104, and the exposed portion of the casing 110 may function as a wellhead 160 to which other elements of the drilling system 100 may be coupled. In the embodiment shown, the drilling system 100 comprises a marine riser 112 coupled between the wellhead 160 and a platform 118 of the rig 102. In certain instances, the riser 112 may comprise multiple joints and may span hundreds of feet from the rig 102 to the well head. The riser 112 may provide a sealed bore between the rig 102 and the wellhead 160, through which a drill string 114 may be introduced at the rig 102 and guided into the formation 104. The riser 112 may also conduct drilling fluid and earth-cuttings from the formation 104 to the rig 102.

In certain embodiments, the riser 112 may be coupled, directly or indirectly, to a telescopic joint 116. The telescopic joint 116 may be secured to the platform 118 via cables 120 and may allow relative axial movement between the riser 112 and the drill rig 102. The axial movement may occur, for example, when the position of the rig 102 changes due to movements in the body of water 106. In certain embodiments, the system 100 may further comprise a tensioner 122 that provides a near constant upward force on the riser 112 at the base of the telescopic joint 116 to prevent the riser 112 from buckling under its own weight.

In certain embodiments, the riser 112 also may be coupled, directly or indirectly, to one or more pressure control and management devices deployed between the rig 102 and the wellhead 160. In the embodiment shown, the pressure control and management devices include blowout preventer (BOP) 124, subsea flow spool 126, and RCD 128. The pressure control and management devices may collectively manage the movement of the pressurized fluids between the formation 104 and the rig 102. The BOP 124, for example, may prevent a flow of fluid from the formation 104 to the rig 102 in the case of a blowout condition. In the embodiment shown, the BOP is coupled between the end of the riser 112 and the wellhead 160, and may comprise a shear-type, a ram-type, or another type that would be appreciated by one of ordinary skill in the art in view of this disclosure.

The flow spool 126 and RCD 128 may be coupled to the end of the riser 112 opposite the BOP 124, and may be at least partially responsible for channeling fluid flowing upwards from the formation 104 into fluid conduits 132. The flow spool 126 and RCD 128 may be coupled to the riser 112 in other positions also. During drilling operations, a drilling fluid or mud is typically pumped downhole from the rig 102 through an internal bore of the drill string 114. The drilling mud travels down through the drill string 114 into the formation 104, where it exits a drill bit (not shown) attached at the end of the drill string 114. Once in the formation, the drilling mud functions to cool the drill bit and remove cutting generated by the formation. In certain instances, the drilling fluid may also function to maintain a pressure balance within the formation 104 so that pressurized fluids trapped within the formation 104 do not flow into the casing 110 and to the rig 102 before the appropriate pressure control systems are in placed.

Once the drilling fluid has exited the drill bit, it may be circulated back to the rig 102 through a riser annulus (not shown), characterized as the annulus between an external surface of the drill string 114 and the internal surfaces of the riser 112 and other pressure control and management devices. In the embodiment shown, the riser annulus may be divided into an upper riser annulus above the RCD 128, and a lower riser annulus below. As will be explained in detail below, the RCD 128 may seal against the outer surface of the drill string 114 while still allowing the drill string 114 to rotate, thereby preventing high pressure formation fluids and drilling mud from entering the upper riser annulus and directing them to the rig 102 through the flow spool 126 and fluid conduits 132 providing fluid communication between the flow spool 126 and pressure control equipment (not shown) located on the rig 102. Notably, the RCD 128 configuration shown may be particularly useful for underbalanced or managed pressure drilling operations, in which formation fluid is allowed to escape from the formation 104 rather than staying trapped within the formation 104 by pressure exerted by the drilling fluid. Underbalanced and managed pressure drilling operations may prevent damage to the formation 104 caused by the pressurized drilling mud, but the released formation fluid must be carefully controlled to prevent blowout conditions from occurring.

In certain instances, it may be necessary to communicate with the RCD 128 once it is deployed. Typically, a wired umbilical is coupled to the RCD 128 at the rig 102 and unspooled as the RCD 128 is lowered into the water. The wire umbilical provides an effective communication channel, but requires additional time and expense in materials and labor. Wireless electromagnetic (EM) communications similarly are difficult when the RCD 128 is positioned under the surface of the water 106, as it is in FIG. 1, because the EM signals are not effectively transmitted through the water 106.

According to aspects of the present disclosure, the RCD 128 may comprise one or more pressure modulators that provide for communication with the rig 102 via mud pulses or other pressure modulations. In particular, pressure modulators at the RCD 128 may generate pressure pulses or modulations that travel through the fluid conduits 132 to the rig 102. In certain embodiments, the conduits 132 may comprise flexible steel pipes or hoses that are deployed from spools 134 at the rig 102. The pressure pulses or modulations traveling within the fluid conduits 132 may be received at one of more receivers 140 coupled to or otherwise in fluid communication within the conduits 132. In certain embodiments, the receivers 140 may be communicably coupled to one or more information handling systems 180 at the rig 102. The information handling system may receive output signals from the receivers and decode the signals to determine the messages or data transmitted from the RCD 128.

FIG. 2 is a diagram of an example RCD 200, according to aspects of the present disclosure. In the embodiment shown, the RCD 200 comprises an RCD body 202 and an RCD bearing assembly 204. The RCD body 202 may comprise a tubular structure that is threadedly coupled to riser 206 and a flow spool 208, forming a bore through which a drill string 210 may be introduced and guided into a formation. The RCD bearing assembly 204 may be positioned within the RCD body 202. In certain embodiments the RCD bearing assembly 204 may be selectively engagable with the RCD body 202, such that it can be stabbed into and coupled to the RCD body 202 and subsequently uncoupled and removed (if necessary) after the RCD body 202 has been coupled to the riser 206. In other embodiments, the RCD bearing assembly 204 may be integrated into the RCD body 202. In the embodiment shown, the RCD bearing assembly 204 is selectively engagable with the RCD body 202 through extendable latches 208 on an exterior surface 210 of the RCD bearing assembly 204, and may seal against an interior surface 212 of the RCD body 202 through one or more seals 214 on the exterior surface 210.

The RCD bearing assembly 204 comprises an internal bore 216 through which a drill string 210 may travel as it is directed downward into a formation. The RCD bearing assembly 204 may further comprise at least one rotating seal. In the embodiment shown, the RCD bearing assembly 204 comprises two rotating seals 218 and 220, one at each side of the internal bore 216. The rotating seals 218 and 220 may seal against an outer surface of the drill string 210, preventing fluid communication from one side of the RCD bearing assembly 204 to the other through the internal bore 216, while still allowing the drill string 210 to rotate, which may be necessary depending on the type of drilling operation.

The area between the outer surface of the drill string 210 and the inner surfaces of the riser 206 and flow spool 208 may be referred to as a riser annulus 250. The RCD 200 may divide the riser annulus 250 into an upper riser annulus 250 a and a lower riser annulus 250 b that are effectively sealed from one another. In the embodiment shown, the RCD 200 seals the riser annulus 250 through the rotating seals 218 and 220 against the drill string 210, and through seals 214 against the interior surface 212 of the RCD body 202. Fluid communication between the upper riser annulus 250 a and lower riser annulus 250 b cannot occur through the internal bore 216 of the RCD bearing assembly 204, or in the space between the RCD bearing assembly 204 and the RCD body 202. In embodiments where the RCD bearing assembly 204 is integrated into the RCD body 202, the seals 214 would not be necessary.

In the embodiment shown, the lower riser annulus 250 b may be in fluid communication with the formation (not shown) in which drilling operations are occurring. The lower riser annulus 250 b may also be in fluid communication with an offshore drilling rig through fluid conduits 224. In contrast, the upper riser annulus 250 a may be open to the drilling rig 102. Drilling fluid pumped downhole through the drill string 210, as well as pressurized formation fluids, may flow upwards to the drilling rig through the lower riser annulus 250 b and hoses 224, exiting the lower riser annulus 250 b and entering the hoses 224 through the flow spool 208. The lower riser annulus 250 b, therefore, may have a higher pressure relative to the upper riser annulus 250 a due to this upward flow of fluid.

As stated above, the RCD 200 may comprise at least one pressure modulator to communicate with a remote rig. Example pressure modulators include mud pulsers, mud sirens, pressure transducers and other pressure modulators that would be appreciated by one or ordinary skill in the art in view of this disclosure. The pressure modulators may generate high or low pressure spikes, or pressure fluctuations with a known frequency, time, or amplitude signature, within the fluid conduits 224 to be received at the drilling rig.

In the embodiment shown, the RCD 200 comprises a first pressure modulator 226. In the embodiment shown, the first pressure modulator 226 comprises a mud pulser positioned at an end of a fluid flow path 228. The mud pulser may comprise one or more valves that selectively open and close to modulate the flow of fluid from the lower riser annulus 250 b to the upper riser annulus 250 a through the fluid flow path 228. When the mud pulser allows fluid flow, the pressure differential between the upper and lower riser annuluses may cause fluid from the lower riser annulus 250 b to flow into the upper riser annulus 250 a. The loss of fluid volume into the upper riser annulus 250 a through the flow path 228 may correspond to a temporary drop in pressure in the upward flow of fluid to the surface. Notably, the amplitude of the pressure modulation may depend on the fluid flow rate through the flow path 228, which may be controlled by partially opening or closing valves within the mud pulser, but which may be bounded on an upper end by the size of the flow path 228. Additionally, the duration of the pressure modulation may depend on the amount of time during which the mud pulser allows fluid flow through the flow path 228.

The RCD 200 may further comprise a controller 230 communicably coupled to the pressure modulator 226. The controller 230 may comprise an information handling system with a processor and at least one memory device coupled to the processor and containing a set of instruction that, when executed by the processor, cause the processor to perform certain actions. Example controllers include microcontrollers or other integrated circuits. In certain embodiments, the controller 230 may be coupled to a power source (not shown) in the RCD 200, such a battery pack, or to a power generator (not shown) that may generated power, for example, using the flow of drilling fluid from the lower riser annulus 250 b to the conduits 224.

In the embodiment shown, the controller 230 may be communicably coupled to the first pressure modulator 226 and may send control signals to the pressure modulator 226. The control signals may be associated with a communication to be transmitted to the surface. The control signals may directly control the positioning of the valves necessary to send a communication to the surface with multiple pressure modulations, or may comprise a signal with an embedded communication that a local controller of the pressure modulator 226 translates into signals that control the positioning of the valves. Notably, a communication from the RCD 200 through the conduits 224 may comprise a binary signal in which the presence or absence of pressure modulations in given time segments may correspond to “1” or “0” bits, which may be resolved and decoded at an information handling system located at the drilling rig.

In certain embodiments, the RCD 200 may comprise one or more sensors (not shown) that may measure one or more conditions of the RCD 200 or conditions within the riser 206 near the RCD 200. Example sensors include temperature sensors, position sensors, pressure sensors, speed sensors, etc. Some or all of the sensors may be communicably coupled to the controller 230, and may communicate measurements to the controller 230. The controller 230 may receive and process the measurements and generate one or more communications to the drilling rig that are associated with the measurements, such as by transmitting the appropriate control signals to the pressure modulator 226. Generating the one or more communication may comprise transmitting to the pressure modulator 226 a control signal associated with a communication containing the received measurement. Example communications may contain, for example, pressure readings from the lower riser annulus 250 b and the upper riser annulus 250 a, temperature readings at the RCD bearing assembly 204, rotation speed of the drill string 210 and rotating seals 218 and 220, force measurements at the RCD bearing assembly 204, and the status of the latches 208 with respect to the RCD body 202. In other embodiments, the RCD 200 may comprise one or more “smart” elements, i.e., elements with their own controllers or control circuitry, coupled to the controller 230 that may communicate status updates with a drilling rig through the controller 230 and pressure modulator 226.

In certain embodiments, the first pressure modulator 226 may comprise a mud siren, rather than a mud pulser. A mud pulser may comprise a rotary valve than generates pressure modulations with a generally sinusoidal shape in response to a flow of drilling fluid. In the embodiment shown, the flow of drilling fluid may either be the flow of drilling fluid through the flow path 228, or the flow of drilling fluid through the lower riser annulus 250 b and the conduits 224. The mud siren may transmit data through phase modulation of the sinusoidal pressure waves by changing the speed of the motor rotating the valve. In the embodiment shown, the controller 230 may be coupled to the mud siren, and may generate communications to the surface by transmitting control signals to the siren that directly control the speed of the motor, or may generate communications to the surface by transmitting control signals to a local controller of the mud siren that directly controls the speed of the motor.

The RCD 200 comprises a second pressure modulator 232. The second pressure modulator 232 may comprise a pressure transducer, which may be used instead of or in addition to first pressure modulator 226. Notably, pressure transducers may both transmit and receive pressure signals, allowing bi-directional communication between the RCD 200 and the drilling rig. In the embodiment shown, the pressure modulator 232 comprises a piezoelectric transducer that generates pressure signals in response to an applied voltage and generates voltages when a pressure signal is received. The piezoelectric transducer may be coupled to the controller 230, for example, which may apply voltages directly to the piezoelectric transducer causing it to generate pressure fluctuations at a frequency, amplitude, and duration determined by the controller 230. Generally, the piezoelectric transducer sends faster but smaller pressure pulses, allowing for an increased bandwidth in the communications with the drilling rig.

The controller 230 may also receive voltages signals generated at the transducer and determine a communication from the drilling rig by decoding and processing the communication. In certain embodiments, the communications from the drilling rig may comprise control signals to downhole elements, including the controller 230. Example communications include control signals intended to cause the extendable latches 208 of the RCD bearing assembly 204 to extend and engage the RCD body 202 or to retract and disengage from the RCD body 202, so that the RCD bearing assembly 202 can be removed from the riser annulus 250. The controller 230 may receive and decode such control signals and generate or forward control signals to the extendable latches 208 to cause the desired actions. In certain embodiments, the control signals from the drilling rig may be directed to the controller 230 and may cause the controller 230 to perform certain actions, such as transmit a certain measurement to the drilling rig or to transmit all available measurements and information to the drilling rig.

FIG. 3 is a diagram illustrating an example information handling system 300, according to aspects of the present disclosure. The example information handling system 300 may be used in a similar form at the drilling rig to receive and decode communications from a RCD and display prompts or control information to a user. Modified or scaled down versions may be used as controllers within the RCD and other element within the RCD, as would be appreciated by one of ordinary skill in the art in view of this disclosure.

A processor or CPU 301 of the information handling system 300 is communicatively coupled to a memory controller hub or north bridge 302. Memory controller hub 302 may include a memory controller for directing information to or from various system memory components within the information handling system, such as RAM 303, storage element 306, and hard drive 307. The memory controller hub 302 may be coupled to RAM 303 and a graphics processing unit 304. Memory controller hub 302 may also be coupled to an I/O controller hub or south bridge 305. I/O hub 305 is coupled to storage elements of the computer system, including a storage element 306, which may comprise a flash ROM that includes a basic input/output system (BIOS) of the computer system. I/O hub 305 is also coupled to the hard drive 307 of the computer system. I/O hub 305 may also be coupled to a Super I/O chip 308, which is itself coupled to several of the I/O ports of the computer system, including keyboard 309 and mouse 310.

FIG. 4 is a flow diagram illustrating an example method 400 according to aspects of the present disclosure. Step 401 of the method comprises pumping drilling fluid into a drill string extending through an RCD. The drilling fluid may be pumped, for example, as part of an on-shore or off-shore drilling operation, both of which may utilize an RCD for underbalanced and managed pressure drilling applications. As described above, the RCD may comprise rotating seals that engage against an exterior surface of the drill string while still allowing the drill string to rotate with respect to the RCD.

Step 402 comprises receiving the drilling fluid from an annulus formed, in part, by the drill string and a tubular in which the drill string is positioned. The tubular may comprise, for example, a riser in an offshore drilling application. Receiving the drilling fluid may include receiving the drilling fluid at a drilling rig through one or more fluid conduits providing fluid communication between the annulus and the drilling rig.

Step 403 comprises generating a modulated pressure signal at the rotating control device. As described above, generating a modulate pressure signal may comprise generating one or more pressure pulses or pressure modulations with known amplitude, time, or frequency signatures. In certain embodiments, generating the modulated pressure signal at the rotating control device may comprise generating the modulated pressure signal with at least one of a mud pulser, a mud siren, and a pressure transducer coupled to the rotating control device. The pressure transducer may comprise a piezoelectric transducer. Generating the modulated pressure signal with the mud pulser may comprise selectively opening and closing valves to allow fluid communication through a fluid flow path of the bearing assembly of the rotating control device.

In certain embodiments, the method may include receiving at least one measurement from at least one of a pressure, temperature, and position sensor coupled to the rotating control device. In those embodiments, step 403 may comprise generating a modulated pressure signal containing the received measurement. Also, in certain embodiments, a modulated pressure signal may be received at the rotating control device. In those embodiments, step 403 may be performed in response to receiving the modulated pressure signal received at the rotating control device.

Step 404 comprises detecting the modulated pressure signal through the received drilling fluid. Detecting the modulated pressure signal may include detecting the signal at a receiver positioned at a drilling rig remote from the rotating control device. The receivers may be communicably coupled to an information handling system, which may receive output signals from the receivers and decode the modulated pressure signal from the rotating control device.

According to aspects of the present disclosure, an example rotating control device may include a bearing assembly with at least one rotating seal and a pressure modulator coupled to the bearing assembly. A controller may be communicably coupled to the pressure modulator. In certain embodiments, the pressure modulator may comprises at least one of a mud pulser, a mud siren, and a pressure transducer. In certain embodiments, the pressure transducer may comprise a piezoelectric transducer.

In certain embodiments described in the preceding paragraph, the rotating control device may further comprise a fluid flow path through the bearing assembly. In certain embodiments, the pressure modulator comprises a mud pulser positioned at an end of the fluid flow path. In certain embodiments, the rotating control device further comprises a seal on an exterior surface of the bearing assembly.

In any of the embodiments of the preceding two paragraph, the bearing assembly further may comprise at least one of a pressure, temperature, and position sensor communicably coupled to the controller. In any of the embodiments of the preceding two paragraphs, the rotating control device may further comprise a selectively extendable latch on an exterior surface of the bearing assembly, wherein the selectively extendable latch is communicably coupled to the controller. In any of the embodiments of the preceding two paragraphs, the controller may comprise a processor and a memory device communicably coupled to the processor, and the memory device contains a set of instructions that, when executed by the processor, cause the processor to receive a measurement from at least one of a pressure, temperature, and position sensor communicably coupled to the controller; transmit to the pressure modulator a control signal associated with a communication containing the received measurement. In certain embodiments, the set of instructions, when executed by the processor, further cause the processor to receive a communication from a remote drilling rig; and perform an action in response to the received communication.

According to aspects of the present disclosure, an example method for downhole communications may include pumping drilling fluid into a drill string extending through a rotating control device and receiving the drilling fluid from an annulus formed, in part, by the drill string and a tubular in which the drill string is positioned. A modulated pressure signal may be generated at the rotating control device. In certain embodiments, generating the modulated pressure signal at the rotating control device comprises generating the modulated pressure signal with at least one of a mud pulser, a mud siren, and a pressure transducer coupled to the rotating control device.

In certain embodiments, generating the modulated pressure signal with the pressure transducer comprises generating the modulated pressure signal with a piezoelectric transducer. In certain embodiments, generating the modulated pressure signal with the mud pulser comprises selectively opening and closing valves to allow fluid communication through a bearing assembly of the rotating control device. In certain embodiments, selectively opening and closing valves to allow fluid communication through the bearing assembly of the rotating control device comprises selectively opening and closing valves to allow fluid communication through a fluid flow path through the bearing assembly.

In any of the embodiments described in the preceding two paragraphs, the method may further comprise receiving at least one measurement from at least one of a pressure, temperature, and position sensor coupled to the rotating control device. In any of the embodiments described in the preceding two paragraphs, generating the modulated pressure signal at the rotating control device comprises generating the modulated pressure signal containing the received measurement. In any of the embodiments described in the preceding two paragraphs, the method may further comprise receiving a modulated pressure signal at the rotating control device. In certain embodiments, the method further comprises selectively disengaging a bearing assembly of the rotating control device from a rotating control device body of the rotating control device is response to the modulated pressure signal received at the rotating control device. In certain embodiments, generating the modulated pressure signal at the rotating control device comprises generating the modulated pressure signal at the rotating control device in response to the modulated pressure signal received at the rotating control device.

Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. The indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. 

What is claimed is:
 1. A rotating control device, comprising: a bearing assembly with at least one rotating seal; a pressure modulator coupled to the bearing assembly; and a controller communicably coupled to the pressure modulator.
 2. The rotating control device of claim 1, wherein the pressure modulator comprises at least one of a mud pulser, a mud siren, and a pressure transducer.
 3. The rotating control device of claim 2, wherein the pressure transducer comprise a piezoelectric transducer.
 4. The rotating control device of claim 1, further comprising a fluid flow path through the bearing assembly.
 5. The rotating control device of claim 4, wherein the pressure modulator comprises a mud pulser positioned at an end of the fluid flow path.
 6. The rotating control device of claim 5, further comprising a seal on an exterior surface of the bearing assembly.
 7. The rotating control device of claim 1, wherein the bearing assembly further comprises at least one of a pressure, temperature, and position sensor communicably coupled to the controller.
 8. The rotating control device of claim 1, further comprising a selectively extendable latch on an exterior surface of the bearing assembly, wherein the selectively extendable latch is communicably coupled to the controller.
 9. The rotating control device of claim 1, wherein the controller comprises a processor and a memory device communicably coupled to the processor, and the memory device contains a set of instructions that, when executed by the processor, cause the processor to receive a measurement from at least one of a pressure, temperature, and position sensor communicably coupled to the controller; transmit to the pressure modulator a control signal associated with a communication containing the received measurement.
 10. The rotating control device of claim 10, wherein the set of instructions, when executed by the processor, further cause the processor to receive a communication from a remote drilling rig; and perform an action in response to the received communication.
 11. A method for downhole communications, comprising: pumping drilling fluid into a drill string extending through a rotating control device; receiving the drilling fluid from an annulus formed, in part, by the drill string and a tubular in which the drill string is positioned; and generating a modulated pressure signal at the rotating control device.
 12. The method of claim 11, wherein generating the modulated pressure signal at the rotating control device comprises generating the modulated pressure signal with at least one of a mud pulser, a mud siren, and a pressure transducer coupled to the rotating control device.
 13. The method of claim 12, wherein generating the modulated pressure signal with the pressure transducer comprises generating the modulated pressure signal with a piezoelectric transducer.
 14. The method of claim 12, wherein generating the modulated pressure signal with the mud pulser comprises selectively opening and closing valves to allow fluid communication through a bearing assembly of the rotating control device.
 15. The method of claim 14, wherein selectively opening and closing valves to allow fluid communication through the bearing assembly of the rotating control device comprises selectively opening and closing valves to allow fluid communication through a fluid flow path through the bearing assembly.
 16. The method of claim 11, further comprising receiving at least one measurement from at least one of a pressure, temperature, and position sensor coupled to the rotating control device.
 17. The method of claim 16, wherein generating the modulated pressure signal at the rotating control device comprises generating the modulated pressure signal containing the received measurement.
 18. The method of claim 11, further comprising receiving a modulated pressure signal at the rotating control device.
 19. The method of claim 17, further comprising selectively disengaging a bearing assembly of the rotating control device from a rotating control device body of the rotating control device is response to the modulated pressure signal received at the rotating control device.
 20. The method of claim 17, wherein generating the modulated pressure signal at the rotating control device comprises generating the modulated pressure signal at the rotating control device in response to the modulated pressure signal received at the rotating control device. 